Wells drilled in low-permeability subterranean formations are often treated by reservoir stimulation techniques, such as hydraulic fracturing, to increase hydrocarbon production rate. High viscosity fluids may be employed to carry proppant down-hole to prop open fractures in the formation. Known linear gels (water containing a gelling agent only) that can be operated at ambient temperature at the surface generally do not exhibit a sufficiently high viscosity to transfer proppant of a large size or large quantity. Consequently, crosslinkers may be used to increase fluid viscosity, providing adequate transport of larger proppant sizes or larger proppant quantity. Higher viscosity fluids also create wider fractures within the formation.
Guar and guar derivatives are among the most often used viscosifying agents, such as polymers, in hydraulic fracturing treatment. Guar derivatives, such as carboxymethyl guar (CMG) and carboxymethyl hydroxypropyl guar (CMHPG), are predominantly used in wells with a high bottom-hole temperature (BHT). Interest in cellulose derivatives, such as hydroxyethyl cellulose (HEC), carboxymethyl cellulose (CMC), and carboxymethyl hydroxyethyl cellulose (CMHEC), has increased for fracturing treatment due to the natural abundance of cellulose.
Often, hydraulic fracturing gels include cross-linking delay additives, gel breakers, and fluid loss control additives among many other possible additives to adapt hydraulic fracturing gel to the circumstances of hydraulic fracturing. A variety of gelling agents and cross-linkers are known for use in hydraulic fracturing gel. For a delay additive, cross-linking reactions are so designed that viscosity development begins after placement of hydraulic fracturing gel deep within a well.
In a related manner, rheology modifiers, such as gel breakers, may be included in hydraulic fracturing gel to significantly decrease viscosity after fracturing for easier removal of the gel from the well. To the extent that the cross-linked gel contains a gel breaker, the gel breaker may be configured for delayed action to maintain desirable properties of the cross-linked gel while fracturing. Even so, additional delay chemistries are desired to adapt rheology modifiers to an increased variety of viscosifying agents and related components.
In addition, fluid volumes in fracturing treatments have increased substantially, while public concern for water use and disposal has also increased. Rather than paying to treat and dispose of produced and flowback water, service companies and operators have pursued recycling in subsequent stimulation operations. “Produced water” refers to water generated from hydrocarbon wells. Generally the term is used in the oil industry to describe water that is produced along with oil and/or gas. “Flowback water” is a subcategory of produced water referring to fracturing fluid that flows back through the well, which may account for some fraction of the original fracture fluid volume.
Produced water, especially from shale plays such as Marcellus and Bakken, is known for its high total dissolved solids (TDS) content. TDS pose challenges for known guar- and guar derivative-based fracturing fluids. Further, various well treatment fluids that are originally prepared with clean water may show lower performance or even fail completely if salty and hard produced water is used in place of clean water. Consequently, produced water intended for recycling in subsequent stimulation operations is treated to obtain a water quality suitable for the fracturing fluids. Even so, such treatment is often cost-prohibitive and time-consuming. Accordingly, other fluids suitable for recycling of produced water are desirable.